Petroleum and/or gas and/or condensates are produced in various environments, and especially in offshore sites and/or in sites that are subject to cold meteorological periods, which leads to substantial cooling of the fluids produced on contact with the cold walls of the transportation pipes.
The term “fluids produced” means fluids comprising petroleum, gases, condensates, water and mixtures thereof.
For the purposes of the present invention, the term “petroleum” means crude oil, i.e. unrefined oil, originating from an oilfield.
For the purposes of the present invention, the term “gas” means crude natural gases, i.e. untreated gases, extracted directly from a gasfield, for instance hydrocarbons such as methane, ethane, propane or butane, hydrogen sulfide, carbon dioxide and other compounds that are gaseous under the exploitation conditions, and also mixtures thereof. The composition of the natural gas extracted varies considerably depending on the well. Thus, the gas may comprise gaseous hydrocarbons, water and other gases.
For the purposes of the present invention, the term “condensates” means hydrocarbons of intermediate density. The condensates generally comprise mixtures of hydrocarbons, which are liquid under the exploitation conditions.
It is known that these production fluids, or fluids produced, usually comprise an aqueous phase. The origin of this aqueous phase may be endogenous and/or exogenous to the underground reservoir containing the hydrocarbons, the exogenous aqueous phase generally originating from injection of water (injection water).
The depletion of the old sites discovered is nowadays leading the petroleum and gas industry to perform production, especially on new sites, often with increasingly great depths for the offshore sites and with ever more extreme meteorological conditions.
On offshore sites, the pipes for transporting the fluids produced, especially on the seabed, are increasingly deep, reaching depths where the seawater is at temperatures below 15° C., below 10° C., or even close or equal to 4° C.
Similarly, on sites located in certain geographical zones, the air or the surface water may be cold, typically below 15° C., or below 10° C. Now, at such temperatures, the fluids produced undergo substantial cooling during their transportation. This cooling may be further amplified in the case of stoppage or a slowdown in production, in which cases the contact time between the fluids produced and the cold walls of the pipe increases.
When the temperature of the fluids produced drops, the industry concerned with extracting these fluids is commonly confronted with the formation of clathrates, also known as hydrate crystals, gas hydrates or quite simply hydrates. The risk for the industry concerned with extracting these fluids and especially concerned with petroleum, gas and condensate extraction is proportionately greater the lower the temperature of the production fluids and the higher the pressure of these fluids.
These problems of formation and/or agglomeration of hydrates may also be encountered in drilling muds or in completion fluids, during a drilling operation or a completion operation.
These clathrates are solid crystals (similar to ice crystals) formed by water molecules, also referred to as the “receiver”, around one or more gas molecules, also referred to as the “guests”, such as methane, ethane, propane, butane, carbon dioxide or hydrogen sulfide.
The formation and growth of hydrate crystals, induced by a lowering of the temperature of the production fluids, which emerge hot from the geological reservoir which contains them and which enter a cold zone, may cause clogging or blocking of the production pipes, the hydrocarbon (petroleum, condensate or gas) transportation pipes, or gate valves, flap valves and other elements liable to become totally or at least partially blocked. These cloggings/blockages may lead to losses of production of petroleum, condensates and/or gas, entailing appreciable or even very substantial economic losses. The reason for this is that the consequence of these cloggings and/or blockages will be a decrease in the production flow rate, or even stoppage of the production unit. In the event of a blockage, the consequence of searching for the zone of the blockage and removal of said blockage will be a loss of time and of profit for this unit. These cloggings and/or blockages may also lead to malfunction in safety elements (for example safety gate valves).
To reduce, delay or inhibit the formation and/or agglomeration of hydrates, various solutions have already been proposed or envisaged. Among these, mention may be made especially of a first solution which consists in dehydrating the crude oil or the gas upstream of the zone of the pipe where the temperature promotes the formation of these hydrates. This solution is, however, difficult or even impossible to implement under satisfactory economic conditions.
A second approach, which is also very expensive, consists in maintaining the temperature of the pipe at a temperature above the temperature of formation and/or agglomeration of hydrates, at a given pressure.
A third approach, which is frequently used, consists in adding a thermodynamic anti-hydrate, for example methanol or glycol, to the fluids produced containing the water/guest gas mixture to shift the equilibrium temperature for the formation of hydrates. In order to obtain acceptable efficacy, about 30% by weight of alcohol, relative to the amount of water, is generally introduced. However, the toxicity of methanol and the large amount of alcohol used are increasingly leading industrialists to adopt a fourth approach.
This fourth solution consists in adding an additive in low dosage, known as a low dosage hydrate inhibitor (LDHI) into the fluids produced comprising the water/guest gas mixture. This additive is also known as an anti-hydrate and is introduced at a low dosage, generally between 1% and 4% by weight, relative to the weight of water, it being understood that larger or smaller amounts are, of course, possible. Two types of anti-hydrate additives are currently known: anti-agglomerants and kinetic anti-hydrates.
The formation of hydrates depends mainly on the temperature and the pressure, and also on the composition of the guest gas(es). To be able to compare the performance of additives, the notion of subcooling value is used. The subcooling (SC) value is thus defined as the difference between the temperature of the fluids produced (or exploitation temperature T) and the thermodynamic equilibrium temperature of formation of the hydrate crystals (Teq) for a given pressure and a given composition of the hydrate-forming gases and of the aqueous phase, according to the following equation: SC=T−Teq.
When the subcooling value is less than or equal to 0° C., there is a risk of formation of gas hydrate.
Kinetic anti-hydrates act on the seeding and growth of the hydrate crystals. They retard the formation of hydrates by several hours, or even several days.
However, this type of hydrate inhibitor acts with difficulty at subcooling (SC) values below −10° C. for a given pressure. In other words, the time for appearance of crystals under these conditions is short enough for them to appear and to increase the pressure loss in the petroleum and gas production fluid transportation pipes.
Conversely, anti-agglomerants do not inhibit the formation of hydrate crystals, but disperse them in the form of fine particles, known as a slurry, which consequently prevents their agglomeration. The hydrates thus dispersed give rise to less or even no clogging or blocking, as mentioned previously, thus limiting the loss of hydrocarbon production.
In contrast with kinetic anti-hydrates, anti-agglomerants make it possible to avoid the problems of blocking and/or clogging as mentioned previously at subcooling (SC) values of the order of −15° C. to −20° C. for a given pressure, but are less efficient or even lose their efficiency at even lower subcooling values.
For example, US 2012/0161070 proposes anti-agglomerant chemical compositions. However, the tests performed are limited to a subcooling value of −17° C. Furthermore, the synthesis of these surfactants requires four reaction steps, if the steps for obtaining the fatty amine from renewable starting materials consisting of fatty acid are also counted. Limiting the number of synthetic steps is important for limiting the cost, the losses of yield, the waste and the quality problems.
US 2012/0157351 also proposes anti-agglomerant chemical compositions. However, the tests performed are limited to a subcooling value of −17° C. and the other chemical compositions proposed are not efficient for dispersing hydrates with a subcooling value of −20° C.
Given the exploitation medium (oceans, seas), it is increasingly common for anti-agglomerants also to have to have low ecotoxicity, satisfactory biodegradability and low bioaccumulation. According to the recommendations of the CEFAS (Centre for Environment, Fisheries and Aquaculture Science) in accordance with the OSPAR (Oslo-Paris Commission), in order for an additive to be green, i.e. environmentally compatible, it needs to meet two of the following three conditions:
1) have an ecotoxicity (LC50 (lethal effects) and EC50 (toxic effects)) of greater than 10 mg·L−1;
2) have a biodegradability (OCDE 306) in marine medium of greater than 60%; and
3) have a bioaccumulation (Log Pow) (OCDE 117) of less than or equal to 3 or its molar mass greater than 700 g·mol−1.
Other countries also impose two of these three conditions for additives used in petroleum and gas production, for instance corrosion inhibitors, kinetic anti-hydrates, anti-agglomerants, mineral deposit inhibitors, de-emulsifiers, deoilers, antifoam additives, paraffin inhibitors and dispersants, asphaltene inhibitors and dispersants, and hydrogen sulfide scavengers.
A real need consequently remains to develop an anti-agglomerant which is easy to manufacture in a low number of synthetic steps and readily industrializable, while at the same time complying with the recommendations of CEFAS or, at the very least, at least one (1), preferably at least two (2), more preferably three (3) of the environmental conditions mentioned above, and which is efficient for a subcooling value of less than or equal to −20° C., i.e. for a temperature difference between the extraction temperature, or exploitation temperature, and the thermodynamic equilibrium temperature at which hydrate crystals form, of less than or equal to −20° C.